BNL-NUREG f O & 65548

AGING AND CONDITION MONITORING OF ELECTRIC CABLES IN NUCLEAR POWER PLANTS ’

RECEIVED Building 130 JUN 1 7 898

O S T I

Robert J. Lofaro, Edward Grove and Peter So0 Brookhaven National Laboratory

Department of Advanced Technology

Upton, New York, USA 11 973-5000 Phone: (51 6) 344-71 91

emai l : lofaro@bnl.gov FAX: (51 6) 344-5569

ABSTRACT There are a variety of environmental stressors in nuclear power

plants that can influence the aging rate of components; these include elevated temperatures, high radiation fields, and humid conditions. Exposure to these stressors over long periods of time can cause degradation of components that may go undetected unless the aging mechanisms are identified and monitored. In some cases the degradation may be mitigated by maintenance or replacement. However, some components receive neither, and are thus more susceptible to aging degradation, which might lead to failure. One class of components that falls in this category is electric cables. Cables are very often overlooked in aging analyses since they are passive components that require no maintenance. However, they are very important components since they provide power to safety-related equipment and transmit signals to and from instruments and controls. This paper will look at the various aging mechanisms and failure modes associated with electric cables. Condition monitoring techniques that may be useful for monitoring degradation of cables will also be discussed.

1.0 INTRODUCTION Aging of components in nuclear power plants has been a

concern for many years, and a great deal of research has been performed to address it. However, the components most commonly studied are active components, such as pumps, valves and circuit breakers. This is probably because these components are obvious candidates to be susceptible to aging degradation since they involve moving parts that are subject to wear. Equally important, however, are passive components that do not receive the maintenance and monitoring attention to which active .

1. Work performed under the auspices of the U.S. Nuclear Regulatory Commission

components are subjected. Passive components serve many important safety functions in a nuclear plant and may also be subject to aging degradation.

Electric cables are one example of a passive component that is susceptible to aging degradation and should be included in an aging management program. They are used extensively throughout all nuclear plants, and they play a vital role in plant safety. The primary aging concern with cables is degradation of the polymers used for the insulation and jackets. Should the insulating properties of the polymers deteriorate sufficiently, failure of the cable could result.

2.0 AGING STRESSORS AND DEGRADATION MECHANISMS There are several stressors that electric cables may be

exposed to in a nuclear plant that can cause them to degrade. Stressors can be imposed by the environment in which the cable is installed, the lcading conditions of the cable, or the method used to install the cable. These are summarized in Table 1, and are discussed in the following paragraphs. Also shown in the table is the relative importance of the stressor in aging degradation of the cable. The rankings were determined from a review and evaluation of past experience and related work in the area of cable polymers (Subudhi and Lofaro, 1996).

As noted in Table 1, the most important stressors affecting aging of electric cables are considered to be exposure to elevated temperatures and radiation. Over long periods of time, these stressors can lead to embrittlement and cracking of the insulation and jackat polymers, which could result in failure of the cable. Therefore, it is important to be able to monitor the condition of the

cable to determine the extent of degradation, and whether the cable is acceptable for continued service.

In a research program being performed by Brookhaven National Laboratory (BNL), various condition monitoring (CM) techniques are being evaluated to determine if they are effective at detecting and monitoring cable degradation. In selecting the techniques to study, the criteria for an effective CM technique were first identified, then a review of promising methods was performed (Lee, 1996). Based on this review the following techniques were selected and are being evaluated in the BNL work:

- Visual lrlspectiori - Elongation-at-Break ,

- Indenter (compressive modulus) - Hardness - Oxidation Inductipn.Time - Oxidation Induction Temperature - Fourier Transform Infrared Spectroscopy - Dielectric Loss - Insulation Resistance - Voltage Withstand - Functional Test

To evaluate these techniques, sample cables were obtained and artificially aged to simulate actual service conditions in a nuclear plant. The aging parameters included thermal aging at 120% (248 9) for 3 hours, followed by exposure to 0.6 Mrad of radiation. These parameters were selected based on a review of typical conditions inside the containment of one specific nuclear plant, and represent approximately 10 years of service exposure in that plant It should be noted that these conditions may not be representative of conditions at other plants.

A second group of cables was artificially aged to simulate 20 years of service based on IEEE Standard 323-1974, which provides guidelines for qualifying safety-related electric equipment. The artificial aging for this group included thermal aging at 150 OC (302 OF) for 650 hours followed by exposure to 25 Mrads of radiation.

Following artificial aging, the cables were subjected to simulated loss of coolant accident (LOCA) conditions, which induded two separate exposures to 75 Mrad of radiation followed by exposure to 7 days of high temperature and pressure steam and chemical spray.

Prior to testing, as well as throughout the artificial aging and accident testing, each of the CM techniques was used to periodically monitor the condition of the cable. The results were then compared with previous results to determine if any trends were evident that could be used to characterize the condition .of the cable.

The BNL work has thus far studied the application of these CM techniques on cables with Neoprene@ jackets and cross-linked polyethylene (XLPE) insulation. Future work will evaluate the effectiveness -of these techniques on other materials.

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3.0 CRITERIA FOR EFFECTIVE CABLE CONDITION MONITORING TECHNIQUES

Monitoring cable condition presents several challenges that must be addressed in selecting an effective condition monitoring technique. The following are several criteria that should be considered in selecting a CM method:

1.

2.

3.

4.

Since it can be very costly to replace a cable, the technique should allow the cable to be tested without being removed. To accommodate this, an effective CM technique should be non-destructive and non-intrusive so that the cable system is not affected by the CM test. In some cases, rnicro- samples may be obtained for testing without causing significant damage to the cable. Techniques that use micro samples may be considered in-situ and non-destructive.

The CM technique should be capable of measuring property changes that can be consistently correlated with a known, standardized amount of cable degradation, and are large enough to enable degradation to be detected and trended. This allows comparisons to be made with previous data to determine if any deleterious trends exist.

It should be applicable to cable types and materials commonly used in existing plants.

It should give reproducible results that are not affected by (or can be corrected for) the test environment.

These criteria were used in selecting the CM techniques for study in the BNL work. The following sections discuss several of the CM techniques being studied in the BNL program, along with some preliminary findings on their effectiveness.

4.0 VISUAL INSPECTIONS In selecting CM techniques for monitoring cable condition, the

first technique to consider is the visual inspection. In comparison to other CM methods which produce quantitative results, visual inspedions provide a qualitative assessment of cable condition. However, visual inspection is an in-situ test which is inexpensive and relatively easy to perform, and can provide useful information for determining cable condition. Therefore, it is considered an important element of any condition monitoring program.

In the BNL program, visual inspections of the test specimens are performed prior to testing (baseline condition), as well as periodically throughout the artiicial aging and LOCA simulation processes. The results obtained throughout the research program are then compared to those obtained from the baseline visual inspection to determine if visible changes in the cable can be correlated to degradation occurring as a result of aging. The visual inspections are performed in a standardized, detailed manner in accordance with a test procedure deveioped by BNL.

The cable attributes which are inspected visually include 1) color, including changes fr.om the original color and variations along the length of cable, and the degree of sheen; 2) cracks, including crack length, direction, depth, location, and number per

. i

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied. or assumes any legal liability or responsibility for the accuracy, completeness, or use- fulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any spc- cific commercial product, process, or service by trade name, trademark, manufac- turer. or otherwise dots not necessarily constitute or imply its endorsement, m m - menduion, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

unit area; and 3) visible surface contamination, including any foreign material on the surface. Also, the rigidity of the cable is qualitatively determined by squeezing and gently flexing it.

As an example of visual inspection results, the cables artificially aged to simulate 10 years of service were examined, along with the second group artificially aged to simulate 20 years of service. Visual inspections were performed prior to artificial aging, and periodically throughout the aging process. The baseline visual inspection showed that both groups of specimens were initially in excellent condition with uniform jacket and insulation colors, no cracks and no visible signs of degradation (Figure 1).

Artificial aging to simulate I O years of service for the first group of cables produced little noticeable change in the cable condition. The jacket and insulation were slightly stiffer, however, they both still had good flexibility. The white insulation was slightly yellow in color after thermal aging. No cracking was evident on the cable jackets or insulation.

For the second group of cables artificially aged to simulate 20 years of service, significant aging degradation was noted. After thermal aging, all of the specimens showed significant signs of degradation (Figure 2). The jackets had areas of grey/silver coloring, while the white insulation appeared dark brown in color. Numerous cracks were noted in the jackets, however, no cracks were found in the insulation. The jacket cracks were circumferential in nature, with most being tightly closed and several opened 1-2 mm exposing the insulation underneath. Small, white, powdery spots were noted near the ends of the jacket on all specimens. The jackets felt brittle with little or no flexibility remaining. The insulation felt moderately rigid, however, it still had some flexibility remaining.

Following artificial aging, both groups of cables were subjected to simulated accident conditions. The performance of the cables was monitored throughout the simulated accident. Both groups of cable showed acceptable performance during the accident testing. ' It is interesting to note that in actual service, cables in such a poor condition as those in the second group would probably be removed from service. However, in the BNL tests these cables still showed acceptable performance when subjected to simulated accident conditions. This would indicate that a good appearance could be a good indicator of an acceptable cable. Future testing will examine this further.

There are several advantages in using visual inspection as a condition monitoring technique. It is relatively easy to perform, and no sophisticated or expensive equipment is needed. Also, it is nondestructive and can be performed in-situ. In this evaluation, visual inspections were performed in a manner which dosety simulates actual plant conditions for installation in a cable tray. The cable specimens were installed in Unistrut channels such that only the top half of the cable jacket was visible. Insulation was examined at exposed ends, similar to what would be found near an end device to which the cable would be connected in the plant.

While the visual results provide useful information on the cable condition, there are limitations as to what can be determined from this information. As was noted during plant walkdowns made during the cable acquisition effort for the BNL work, many cables are not easily accessible for inspection. Some cables are installed in closed conduits, and it is not possible to visually observe them. Also, cables installed in cable trays can be buried under other cables making it very difficult to visually inspect them without disturbing other cables in the tray. These limitations apply to all CM techniques that require access to the cable.

The preliminary results obtained thus far indicate that visual inspection is a useful tool and should be part of any cable condition monitoring program.

5.0 ELONGATION-AT-BREAK Elongation-at-break (EAB) is a proven technique for measuring

degradation in polymers. It is a measure of a material's resistance to fracture under an applied tensile stress and is commonly used to assess the loss in mechanical integrity when a material is exposed to a service environment. The drawback to this technique is that it is destructive. Pieces of cable must be removed and destructively tested to obtain EAB data.

In the BNL program, EAB was used as a reference technique. Results from the other techniques being studied were compared to EAB as a measure of their effectiveness. Specimens of insulation (conductor removed) and jacket were tested in an lnstron tensile tester after they had undergone sequential thermal aging and gamma-imdiation. Figure 3 shows EAB data for XLPE insulation and Neoprene@ jacket materials after they had undergone various stages of artificial aging. Figure 3 shows that after artificial thermal and irradiation aging to simulate 10 years of service in a power plant, the EAB of XLPE and Neoprene@ have not significantly changed from the as-received condition. However, after each of the two 75 Mrad irradiations to simulate accident conditions, and the LOCA steadchemical spray, the EAB for XLPE shows a significant decrease. Neoprene@ also shows an EAB loss after the accident irradiations, however, a slight increase after the LOCA steam testing. This could be due to the absorption of moisture which acts as a plasticizer.

Results to date show that EAB testing offers a promising technique for monitoring the rate of degradation of cable materials.

6.0 COMPRESSIVE MODULUS MEASUREMENT One promising new method of monitoring cable condition is by

measuring the compressive modulus of the jacket and insulation material. Compressive modulus is the ratio of compressive stress to compressive strain below the proportional limit. It can be measured using a device such as the Indenter Polymer Aging Monitor, developed by the Electric Power Research Institute (EPRI).

The Indenter, which is shown schematically in Figure 4, is a portable measuring system which pushes a probe against the

material to be measured and records the force applied and the resulting displacement of the probe. It is controlled by a personal computer, which calculates the compressive modulus from the readings obtained. This device was designed to be used insitu in a plant, or in a laboratory setting. The probe used has a rounded tip which compresses, but does not puncture the material under test.

Practical limitations of the cable installation determine which cables can be tested using the Indenter. For example, cables which are installed in a conduit or stacked in the bottom of a cable tray would not be readily accessible for this type of test. Also, it should be noted that insulation condition, and not jacket condition, is the most important criteria for determining cable acceptability. Since the cable insulation is typically covered by the jacket over the majority of the cable run, indenter measurements would need to be taken in areas where the insulation is exposed, such as near terminations. The drawback to measuring compressive modulus near terminations is that they could be far removed from areas of concern, such as hot-spots, where cable degradation could be greatest. Also, for the majority of the cable, the insulation is shielded to some extent by the jacket from the service environment. Therefore, a correlation between jacket condition and insulation condition would need to be developed, which would require experimental data.

Measurement of compressive modulus may be an effective method of monitoring polymeric materials whose properties change in proportion to the cumulative effects of thermal and radiation aging. Previous experience with the Indenter (Shook, 1988, Subudhi, 1996, Toman, 1993) has shown promising results for Ethylene Propylene Rubber (EPR), Chloro-Sulfinated Polyethylene (CSPE), Polyvinyl Chloride (PVC), Neoprene@, Butyl Rubber (BR) and Silicone Rubber (SR). This method has been less successful on XLPE materials.

As an example of the effect of aging on compressive modulus, Figure 5 presents Indenter measurements on Neoprene@ cable jackets subjected to artificial aging simulating 10 years of service. As shown, the artificial thermal and irradiation aging to simulate service exposure produces t i le change in compressive modulus. Subsequent exposure to accident radiation exposures of 75 Mrad each, and LOCA steam exposure produces an increase in the compressive modulus, indicating a hardening of the material.

Preliminary results from the BNL work show definite trends in the compressive modulus following exposure to thermal and radiation aging. Exposure of cables to low levels of thermal and radiation aging tended to have only a slight effect on the modulus (however, longer aging exposures, e.g., 20 year equivalent thermal exposure and accident radiation, tended to produce a much higher compressive modulus). For both Neoprene@ jackets and XLPE insulation, thermal aging appeared to have the greatest effect on compressive modulus.

In performing the baselineindenter measurements, specimen- to-specimen variations were noted in the modulus values. Even though the jacket and insulation materials were the same between specimens, the compressive modulus for different

source samples differed. This is indicative of variations due to chemical composition and/or manufacturing differences. Based on this observation, it appears that the availability of baseline data for new cables would be important for the indenter to provide a useful assessment of a cable's condition throughout its life.

7.0 OXIDATION INDUCTION TIME MEASUREMENT It is known that oxidation is retarded for a finite period of time

by antioxidants that are added to the materials used to manufacture cable jackets and insulation. However, when these antioxidants have been consumed, the main polymer structure begins to oxidize. This is detected by the appearance of an exothermic peak in the experimental curve. By determining the time taken to commence oxidation, an estimate may be made of the antioxidant level remaining in the cable material. This gives an indication of the material's ability to withstand oxidative degradation.

To evaluate this technique, oxidation induction times (01 times) have been measured for insulation and jacket materials using a Shimadzu DSCSO differential scanning calorimeter. This instrument measures the time taken for specimens to undergo oxidation in an oxygen environment at a preselected temperature.

Figure 6 shows a family of curves for oxidation induction time for XLPE insulation. Note that the curves have been spread vertically along the Y axis to facilitate comparison. In their original location, the curves lay on top of each other with the start of the curves passing through the zero point on the Y axis. This axis gives a measure of the energy supplied to the specimen during the experiment. The units are in milliwatts per mg of material. A peak represents an exothermic oxidation reaction.

Close examination of the curves shows that shortly after the curves become horizontal, indicating that the set temperature has been reached, there is a small blip in the line. This is the time (to) at which the nitrogen around the specimen is switched to oxygen. When the homontal l i e shows an increase in gradient it indicates that oxidation of the specimen begins. This time (6) is measured with the associated software using the tangentlintercept method. The 01 Time is the difference between these two values. The software is also used to measure the temperature at the start of oxygen introduction and the commencement of oxidation. These values are given in the figures. The actual test temperature deviates slightly from the programmed temperature of 22OOC (428OF), and averages about 218.S°C (425.3OF).

From Figure 6, it may be seen that for as-received XLPE specimens (baseline) the time to induce oxidation is approximately 103 min. When the material is thermally aged to simulate 10 years of service, it does not change the oxidation induction time significantly. Nor does the low gamma dose that simulates 10 years of service (0.6 Mrad). The oxidation induction times remain the same as for as-received XLPE.

However, for the very large irradiation doses of 75 Mrad to simulate accident radiation, there is a large decrease in the oxidation induction time. This indicates that the XLPE, after

radiation, becomes more susceptible to oxidative degradation. due to the loss of antioxidants. The oxidation induction time for XLPE exposed to a simulated LOCA steadchemical spray is further reduced to about 30 min.

From the preliminary data, its seems that oxidation induction time measurements are very valuable in determining if the base structural cable material is susceptible to rapid oxidation as a result of the loss of antioxidant.

8.0 CONCLUSIONS Aging of electric cables can be addressed in plant aging

management programs to mitigate the effects of degradation, which could cause cable failure in the event of an accident. Recent research indicates that there are several potentially effective methods of monitoring cable condition. While each has its limitations, which should be considered in its application, these techniques can be used to characterize the condition of electriccables and provide insights into their remaining life. The most effective condition monitoring program for cables would probably be a combination of two or more techniques that provide

a morecomprehensive characterization of cable condition than any one technique can provide.

9.0 REFERENCES

Carfagno, S.P., et. at., “Development of a Cable Indenter to Monitor Cable Aging In-situ,” OPERA ‘89, Lyon, France, 1989.

Lee, B.S., “Condition Monitoring Research Plan for Low-Voltage Electric Cables,” Brookhaven National Laboratory Technical Report TR-6168/69-03-95, 1996.

Shook, T.A., and Gardner, J.B., ‘Cable Indenter Aging Monitor,“ EPRI NP-5920, 1988.

Subudhi, M. and Lofaro, R., ‘Literature Review of Environmental Qualification of Safety-Related Electric Cables,” NUREGICR- 6384, Vols. 1 and 2, 1996.

’

Toman, G.J., et. al., %-Plant Indenter Use at Commonwealth Edison Plants,” EPRl TR-102399, 1993.

High Temperature

Radiation

Humidity

Vibration Can accelerate the degradation rate of other stressors. Low

Damage to jacket or insulation due to repeated scraping or abrasion on sharp edges.

Can cause ohmic heating leading to higher operating temperatures in power cables. (No significant effect in I&C cable)

Medium

Medium High Current

Stressors due to Instatlation

Can cause hardening and embrittlement of jacket and insulation material.

Can cause hardening and embrittlement of jacket and insulation material.

High

High

Can accelerate the degradation rate of other stressors. Low

~ Bends Accelerate degradation of other stressors by imposing concentrated

Accelerate degradation of other stressors due to heating by other

Low compressive and tensile stresses on cable at the location of the bend.

cables in close proximty; compressive stresses due to weight of other cables on top.

Cable Trays Low

Vertical Runs Creep damage to jacket and insulation due to weight of the cable. Low

Physical Damage Damage to jacket and/or insulation. (4 Improper Installation Damage to jacket and/or insulation. (a) Overhangs Damage to jacket or insulation due to scraping or abrasion on sharp Low

edges.

(a) Plant dependent.

Figure 2 Typical cable condition after thermal aging at 650 F for 250 hours.

I E3 Insulation (all colors) El Jacket I Baseline

Thermal aging (3 hrs @ 120C)

Service radiation (0.6 Mrad)

Accident Radiation (75 Mrad)

Accident Radiation (75 Mrad)

LOCA Steam Exposure ..

0 100 200 300 400 500 600 700

EA6 (“A)

Figure 3 EAB data for XLPE insulation and Neoprene@ jackets before and after artificial aging and accident testing.

Knurled Nut

Sliding Clamp Head

Sliding Bar I Tensioning Cam h e r MufdlPin / Connector

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Access Door Conapl Panel

Figure 4 Schematic diagram of the Indenter Polymer Aging Monitor

Baseline

Thermal aging (3 hrs @ 120C)

Service radiation (0.6 Mrad)

Accident Radiation (75 Mrad)

Accident Radiation (75 Mrad)

LOCA Steam Exposure

0 2 4 6 8 1 0 1 2 1 4 Compressive Modulus (Newton/rnm)

Figure 5 Compressive modulus measurements on Neoprene@ cable jackets before and after artificial aging and accident testing.

DSC mW/mg

218.376 29.09min '

M C A test 59.72min

1106CB1 75 M n d

L 1 1 0 6 D B l 0.6 M n d 218.35C

1 yc k 4 6 m i n

58.7Smin

218.35C 32.05min llO8FBl

75 M n d

-0.8

-2.80-

, I 0.00 100.00 200.00

Timc[min]

FileNam: I106PEBKWO Duestor Typc: Shinmdzu DSC50 Acquisition Due: 9711 1/22 Sample Namc: We@: cell: Aluminum Atmmphcrc oxygal Rptc Flow 50.CXlfmVnainJ opentor Ps Connnmt: RUNS AT 22OC

BLK XLPE INSUL 0106

Tunphgram Rate Hold Tcnp Hold TLnc

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Figure 6 Oxidation induction times for XLPE insulation before and after artificial aging and accident testing.

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